Contract number: TREN/07/FP6EN/S07.70123/038509 European Transmission System Operators European Wind Integration Study (EWIS) Towards a Successful Integration of Wind Power into European Electricity Grids EWIS Wind Turbine Model Validation Report Revision [Final Version – Including EWEA meeting outcome: 15.12.2008 – WG3] [Version 3.0 - Including EWEA Feed Back: 04.12.2008 – WG 3] [Draft Version 2.0: 02.06.2008 – WG3] [Draft Version 1.0: 15.04.2008 – WG3]
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Contract number: TREN/07/FP6EN/S07.70123/038509
European Transmission System Operators
European Wind Integration Study (EWIS) Towards a Successful Integration of Wind
Power into European Electricity Grids
EWIS Wind Turbine Model Validation Report
Revision [Final Version – Including EWEA meeting outcome: 15.12.2008 – WG3]
[Version 3.0 - Including EWEA Feed Back: 04.12.2008 – WG 3] [Draft Version 2.0: 02.06.2008 – WG3]
[Draft Version 1.0: 15.04.2008 – WG3]
Content EWEA Feedback on the ‘EWIS-Wind Turbine Model Validation Report’ .....................................4 1. Validation of Wind Turbine models ....................................................................................7 1.1. Introduction .............................................................................................................................7 1.2. Current wind power supply and harmonised models for wind turbine....................................8 1.3. Test System............................................................................................................................9 1.3.1. Generator Types ..............................................................................................................11 1.3.2. Type of Investigations ......................................................................................................11 1.3.3. Grid Connection Requirements........................................................................................12 1.4. Visualisation of the results....................................................................................................13 1.5. Results..................................................................................................................................13 1.6. System parameters ..............................................................................................................14 1.7. Exemplary Results................................................................................................................18 2. Wind turbine models based on grid code requirements in Germany...........................24 2.1. Wind Turbine Protection .......................................................................................................26 2.2. Wind farm based on double fed induction generators..........................................................27 2.3. Wind farm based on squirrel cage induction generators......................................................34 2.4. Wind farm based on full size inverter model ........................................................................35 3. Wind turbine models based on grid code requirements in Spain.................................36 3.1. Objectives .............................................................................................................................36 3.2. Grids used for the test ..........................................................................................................37 3.3. REE grid used to test wind turbines .....................................................................................37 3.4. Wind turbine models.............................................................................................................40 3.5. Doubly fed induction generator model..................................................................................45 3.6. Squirrel cage induction generator model..............................................................................57 4. Grid code requirements and wind turbine models used in Czech Republic................81 4.1. Grid code requirements ........................................................................................................81 4.2. Squirrel cage induction generator model..............................................................................82 4.3. Double Fed Induction Generator model ...............................................................................85 5. Validation of Wind Turbine Models - SCIG - in Denmark................................................89 5.1. Introduction ...........................................................................................................................89 5.2. Test System..........................................................................................................................89 5.3. Wind Turbine Model with SCIG ............................................................................................91 5.3.1. Electric Parameters ..........................................................................................................91 5.3.2. Mechanical System Representation.................................................................................92 5.3.3. Compensation of Reactive Power....................................................................................94 5.3.4. Protection System ............................................................................................................95 5.4. Analysis of the Test System with SCIG Wind Turbine .........................................................96 5.4.1. Three Phase short circuit, UPCC = 0.2 p.u. .......................................................................96 5.4.2. Three Phase short circuit, UPCC = 0.8 p.u. .......................................................................99 5.5. Influence of Two – Mass Model..........................................................................................102 5.6. Conclusions and Recommendations..................................................................................105 5.6.1. Recommendations for Simulation Settings ....................................................................106 5.7. Appendix - SCIG, Denmark ................................................................................................107 5.7.1. Simulation Results with PowerFactory – Load Flow......................................................107 5.7.2. Simulation Results with Two-Mass Model in PowerFactory ..........................................109 6. Validation of Wind Turbine Models - DFIG - in Denmark..............................................112 6.1. Introduction .........................................................................................................................112 6.2. Test System........................................................................................................................112 6.3. Wind Turbine Model with DFIG ..........................................................................................114
2
6.3.1. General Structure of the Model ......................................................................................114 6.3.2. Electric Parameters ........................................................................................................114 6.3.3. Mechanical System Representation...............................................................................116 6.3.4. Control System of the Wind Turbine ..............................................................................117 6.3.4.1 Generator and Rotor Side Frequency Converter ...........................................................117 6.3.4.2 Grid-Side Frequency Converter .....................................................................................121 6.3.5. Protection System - Crowbar .........................................................................................121 6.3.4.3 General Remarks ...........................................................................................................121 6.3.4.4 Influence of Crowbar Resistance Size on the Machine Behaviour ................................124 6.4. Analysis of the Test System with DFIG Wind Turbine........................................................124 6.5. Conclusions and Recommendations..................................................................................125 6.5.1. Recommendations for Simulation Settings ....................................................................126 6.6. Appendix DFIG - Denmark .................................................................................................127 6.6.1. Simulation Results with PowerFactory – Load Flow......................................................127 6.6.2. Block Diagrams of the Enhanced Wind Turbine Model .................................................128 6.6.3. Simulation Results for Dynamic Analysis.......................................................................131 6.6.4. Influence of Crowbar Resistance on Behavior of the Machine ......................................135 7. References ........................................................................................................................137
3
EWEA Feedback on the ‘EWIS-Wind Turbine Model Validation Report’
⇒ EWIS received EWEA Feed Back to
Wind Turbine Model Validation Report
⇒ Provision of Real Measurements
⇒ WT-Model Validation discussed with
EWEA adds more value to EWIS
investigations.
• EWEA - Time duration for the grid disturbance (150 ms) is not sufficient to
demonstrate the reactive current support and active power production during the
voltage dip-
EWIS have used even longer time duration like 500 ms and the WT models fulfill
the requirements like reactive current support and active power production during
1.3. Test System The wind turbine models used within the study have been verified using a simple test
system with an infinite bus, a voltage source transformer and the respective wind turbine,
see Figure 1-1, where the tap changer is fixed:
1
2 3
Figure 1-1: Test system
Additional parameters for this test system can be found in and Table 1.
Assumptions:
MVASk 3000=′′
1.0=n
n
XR
fZ
kV110
kV20 kV690.0
Fault
%650==
cc
n
UMVAS
%1150==
cc
n
UMVASGrid Equivalent Wind Turbine
gZ wZ
MWPw 45=20/11012 =r 69.0/2023 =r
Pcc
1
2 3
MVASk 3000=′′
1.0=n
n
XR
MVASk 3000=′′
1.0=n
n
XR
fZ
kV110
kV20 kV690.0
Fault
%650==
cc
n
UMVAS
%1150==
cc
n
UMVASGrid Equivalent Wind Turbine
gZ wZ
MWPw 45=20/11012 =r 69.0/2023 =r
Pcc
9
• Transformers: Pcu = PFe = 0 MW
• Grid equivalent: voltage factor c = 1.0 .(although 1.1 is also correct [10])
In order to transform the equivalent grid parameters into the p.u. system, some
calculations are necessary:
( )Ω=== 033.4
30001100.1 2
''
21
MVAkVx
S
UxcZ
k
g
Ω=Ω=⇒=+= 4013,0013.41.0222
ggg
gggg RandX
X
RandXRZ
10
1.3.1. Generator Types
It has been decided, that three types of wind turbine should be taken into account, these
are
a) The squirrel cage induction generator (with or without fast voltage support),
b) The doubly fed induction generator and
c) The full size inverter model.
For the two latter ones the reactive power exchange at the point of common coupling is set
to zero.
1.3.2. Type of Investigations
To compare the behaviour of the wind turbine models, several investigations have been
made connecting the different wind turbine types to the test system.
A 150 ms symmetrical three-phase short circuit at the point of common coupling (PCC)
bus has been simulated with a voltage dip at the 110 kV node to
• 80%,
• 50% and
• Less than 30% of nominal voltage
To calculate the fault impedance to reach the desired voltage dip it has been used the
methodology of IEC [10].
• To obtain the voltage of 0.2 p.u. at the PCC, the fault reactance is set to 0.965 Ω.
• To obtain the voltage of 0.8 p.u. at the PCC, the fault reactance is set to 15.45 Ω.
Asymmetrical faults have not been investigated because no influence on the overall
system security is expected.
11
1.3.3. Grid Connection Requirements
Generally, there are several grid connection requirements for wind turbines valid in several
TSO regions, see some examples shown in Figure 1-2.
Special characteristics, such as fault ride through capability; voltage support or voltage
control depend on the national grid codes.
One of the study´s objectives is to investigate the effect of grid codes changes or their
adaptations on the overall system behaviour.
Figure 1-2: Present Situation: Different Grid Codes in Europe Thus, to achieve this goal with the models used in this study, a calibration possibility is
required which enables the turbine models to fulfil the European grid code requirements
e.g. with respect to
• Fault Ride Through Capability,
• Contribution to voltage support characteristics,
• Contribution to frequency maintenance.
12
1.4. Visualisation of the results
In terms of comparison the following variables have been visualized and compared:
• The generator voltage at the 20 kV generator bus bar and the 110 kV point of
common coupling (PCC) in [p,u.],
• Active and reactive power in [MW] resp. [MVar] at the 110 kV PCC,
• Active and reactive current in [kA] or [p.u.] at the 110 kV PCC,
1.5. Results
The results of the different wind turbine models connected to the test system have been
compared and evaluated. It was concluded that the respective wind turbine models, which
then are used in the study, behave in a way they are expected to do after initiated faults in
the test system.
Some exemplary graphics calculated with several software tools are presented for the
Doubly Fed Induction Generator WT Model and for the remaining two types of the WT
models namely squirrel Cage Induction Generator and Full Size Inverter Model. The
detailed results of all types of WT Models (model description and behavior) based on
various grid code requirements.
The example of the DFIG during a symmetrical three phase fault at the 110 kV PCC with
UFault = 0.2 p.u. for a wind farm with P = 30 *1,5 MW with voltage support is shown,
visualizing a simulation period of 1 second. The other respective investigations on different
turbine types and grid faults have been executed accordingly, but are not documented in
this report.
13
1.6. System parameters
System Component Parameter Value
c – Factor 1.
Voltage Magnitude Setpoint
1 pu
Equivalent Grid
Voltage Angle Setpoint
0°
Copper Losses – PCu 0 kW
No Load Current – I0 0 %
No Load Losses – PFe 0 kW
Vector Group HV-Side
YN
Vector Group LV-Side YN
Transformer 110/20 kV
Phase Shift 0°
Copper Losses – PCu 0 kW
No Load Current – I0 0 %
No Load Losses – PFe 0 kW
Vector Group HV-Side
YN
Vector Group LV-Side YN
Transformer 20/0.69 kV
Phase Shift 0°
Table 1 Additional System Parameters
The fault reactance in case of URES=0.2pu is equal to 1Ω and in case of URES=0.8pu is
Table 4: Summary of electrical parameter settings *) Such a high value results from the assumption of the basis current for the rotor one of
the software tools
16
Parameter Value Base Power – PBASE 5 MW Turbine Damping - DTUR 0 Nms/rad Inertia of the Turbine – JWTR 6.1·106 kg m2 Inertia of the Generator – JGEN 101.72 kg m2 Shaft Damping - DSHAF 1.4·106 Nms/rad Stiffness Constant – kms 8.3·107 Nm/rad Nominal Angular Speed of
Turbine 18 rpm
Inertia of Equivalent Generator - JEQV=30xJGEN
3051.6 kg m2
Table 5: Summary of mechanical parameter settings
17
1.7. Exemplary Results
Exemplary results for the DFIG, exposed to a 150 ms three phase Test Fault with UFault =
0.2 p.u. - Crowbar operation in the range of 0.4 … 0.1 sec adjustable. With compliance to
the EWEA feedback and measurement a crow bar operation of 0.4 sec. will be adjusted in
Conditions: • Reactive power flow directed to wind farm • Voltage dip below 85%
Condition: voltage dip below 80%
Tripping of WT within 100 ms
Conditions: voltage about 120% or frequency exceeds limits 47.5 Hz – 51.5 Hz
Power reduction about 50.2 Hz
CCoonnnneeccttiioonn PPooiinntt
Fault Ride Through Contribution to voltage maintenance Contribution to frequency maintenance
Figure 2-2: [IEEE 2006, Montreal] Wind Farm Frequency Characteristics
24
PΔfNet
Power reduction
Frequency
P M Available power
P Δ
Hz50fHz50.2P20ΔP Netz
M−
=
fNet 50.2 Hz
ΔPΔP=40% PM / Hz
At fNet ≤ 47.5 Hz and fNet ≥ 51.5 Hz separation from grid
Between 47.5 Hz ≤ fNet ≤ 50.2 Hz no limitation
fNet
at 50,2 Hz ≤ fNet ≤ 51,5 Hz
Figure 2-3: [IEEE 2006, Montreal] DFIG and full size inverter model are fulfilling all grid code requirements in Germany
• FRT capability • Voltage support / voltage control • Power reduction in case of over frequency (Figure 2-3)
Squirrel cage induction generator (SCIG) model represents the old WT-installations and cannot fulfil the grid code requirements in Germany [7]. For this model no voltage support and FRT capability are adjusted. It is proposed to change the connection requirements for old installations to reduce the outage of wind power generation in case of voltage drops in Germany as followed:
• Delay of the trip signal in case of low voltage for 250 ms • No voltage support • Power reduction in case of over frequency (Figure 2-3)
25
2.1. Wind Turbine Protection Each wind turbine model is equipped with under voltage protection. The settings for the excitation, trip delay and tripping of the generator is adjustable. The following settings are adjusted within the models: DFIG, DDSM: U<< 0.15 pu (FRT capability, trip below 0.15 pu) U>> 1.20 pu Trip f>> 50.2 Hz (Reduction of active power generation) f<< 47.5 Hz Trip f>> 51.5 Hz Trip SCIG U<< 0.8 pu Trip U>> 1.10 pu Trip f>> 50.2 Hz (Reduction of active power generation) f<< 47.5 Hz Trip f>> 51.5 Hz Trip
26
2.2. Wind farm based on double fed induction generators The model which was developed jointly with the manufacturers, the FGW and the
transmission system operators and which also includes voltage support was used in the
investigations. The wind turbine model was adapted to the German Transmission code
requirements (TC 2007) (Fault Ride Through, voltage support, system automatics, active
power reduction in case of over frequency). For the most part the currently commissioned
wind turbines do not have to meet any extended connection conditions such as voltage
support due to the time of application. Nevertheless all wind turbines with voltage support
connected to the interconnected power system after 2004 were taken into account for the
dynamic investigations of the 2008 and 2015 variants.
Table 10: Parameter of SCIG given in [16] transformed into p.u.-System However, the SCIG model analyzed in [16] was connected to a grid at the voltage level
0.96 kV. In order to connect this generator to the defined test system from [15], the rated
voltage of the generator was changed to Un=0.69 kV in the simulation software. The p.u.-
parameters of the machine have not been changed. Moreover, the rated power of the
machine has been modified according to [15] and set to Sn_FARM=22*Sn=50.6 MVA. As
91
setpoint for the simulation the active power of the machine has according to [15] been set
in PowerFactory to P=44 MW. The slip value and reactive power drawn by the machine
from the grid has been automatically determined by PowerFactory using the internal
machine parameters.
5.3.2. Mechanical System Representation
The mechanical system of the wind turbine has in a first step been represented as
lumped-mass model. The equivalent inertia for the whole farm with Sn_FARM=50.6 MVA has
been calculated using the parameters of the two-mass system given in [16] for the wind
turbine with Sn=2.3 MVA, which are summarized in Table 11.
Parameter Value
Inertia of the Turbine – JWTR 4.176·106 kg m2 Inertia of the Generator– JGEN 93.22 kg m2 Stiffness Constant – kms 8.949·107 Nm/rad Gear Box Ratio – fGB=nGEN/nWTR 80
Table 11: Parameter of Mechanical Parameters of WT with Sn=2.3 MVA [16]
Using given parameters of the mechanical system the inertia constant H has been
calculated for the 2.3 MVA wind turbine using Eq. (2) according to [17].
n
m
SJH
205.0 ω⋅
= (2)
Where J – is the inertia in kg m2, ω0m – is the nominal mechanical angular speed in rad/s
and Sn – is the rated apparent power in MVA.
Since the nominal angular speed of the turbine and the generator are different and are
related to each other by the gear box ratio – fGB, the right value has to be used for the
calculation of inertia constants of both elements. With this in mind the following values of
the angular speed have been used for the generator and the turbine – Eq. (3) and Eq. (4),
respectively.
⎥⎦⎤
⎢⎣⎡=⋅=⋅=− sradnGENm 0796.157
6021500
602
00ππω (3)
92
⎥⎦⎤
⎢⎣⎡=⋅⋅=⋅⋅=− srad
fn
GBWTRm 9635.1
801
60215001
602
00ππω (4)
Moreover, it was assumed that for the calculation of the inertia constant of the turbine the
same value of Sn=2.3 MVA as in case of the generator is used.
The resulting inertia constants for the generator and the turbine obtained with parameters
from Table 11 are given by Eq. (4) and Eq. (5), respectively.
5.0=GENH (5)
4999.3=WTRH (6)
For the lumped-mass model the equivalent inertia constant is treated as a sum of the
inertia constant for the generator and for the turbine [18] and equals for the considered
wind turbine HOneM=3.9999.
In the analysis at hand the whole farm is represented as one single large equivalent unit
with Sn_FARM=50.6 MVA. It has been assumed that the inertia constant H has the same
value as in case of the small unit (Sn=2.3 MVA), which has been scaled up in order to
represent the farm equivalent, since it is in per unit [17].
This constant HOneM can directly be applied for the simulation of the farm behavior in some
software packages. However, the tool PowerFactory requires the definition of the inertia J
in [kg m2]. For this purpose the value of inertia for the whole farm JFARM has been
calculated with Eq. (7).
262_2
0
52.16405106.500796.1579999.322 mkgSHJ FARMn
GENm
OneMFARM =⋅⋅
⋅=⋅
⋅=
−ω (7)
The resulting equivalent inertia of lumped-mass system of the farm can be also calculated
according to Eq. (8).
TURBGB
WTRGENFARM N
fJ
JJ ⋅⎟⎟⎠
⎞⎜⎜⎝
⎛+= 2 (8)
Where the JGEN and JWTR are inertias for the original turbine with Sn=2.3 MVA, fGB – is the
gear box ration and NTURB is the number of wind turbines collected to one single equivalent
unit. In this case NTURB=22.
93
The stiffness of the shaft given in Table 11 was transformed into the per unit system using
Eq. (9) according to [19].
47748.0280502
103.210949.8
226
7
220 =
⋅⋅⋅
⋅⋅⋅
=⋅
⋅=πω
pfSkK
GBBASE
msms (9)
Where p – is the number of pole pairs and the obtained value of stiffness - Kms is
expressed in pu/el. rad.
5.3.3. Compensation of Reactive Power In the test system defined in [15] there is no information about the compensation of
reactive power drawn by the SCIG.
However, test simulations in PowerFactory performed without any compensation device
show that the reactive power value in the point of common coupling on the 110 kV level is
significantly higher than the one given on the curves from [15].
The value given in [15] is approximately equal to 14 MVar (Figure 6, [15]), while the value
obtained in the simulation with PowerFactory without compensation is equal to 34.4 MVar,
see Figure 5-8.
Thus, in order to get the same reactive power value on the 110 kV level an additional
capacitor has been connected to the connection node of the SCIG at 0.69 kV level.
The size of the capacitor has been adjusted to obtain the desired reactive power level at
the 110kV-PCC and was equal to 39326 µF – which corresponds to 17.65 MVar.
According to [16] the capacitor bank has been represented as Delta – circuit. The
respective results, which are similar to the results from [15] can be found in Figure 5-9
94
5.3.4. Protection System
Wind turbines are generally equipped with a complex protection system. This system
controls various parameters of the wind turbine, as e.g. the mechanical, the thermal and
the electric parameters. In case of exceeding a defined limit concerning some parameter,
the wind turbine is disconnected from the grid. In case of electric parameters the voltage
and the frequency as well as the current are observed. The protection scheme used in the
wind turbines with SCIG causes immediate disconnection from the grid in case of under-
voltage in case of a grid fault.
The default behavior of the protection system can be different in each country according to
the TSOs' requirements defined in the respective GridCode.
The Danish grid code for Wind Turbines above voltages of 110 kV [20] states:
"The wind farm shall be equipped with voltage and frequency relays for disconnection of the wind farm at abnormal voltages and/or frequencies. The relays shall be set according to agreement with the regional grid company and the system operator. The protective functions of the wind turbine shall have settings and time delays meeting the requirements in section 8.2. [..] By means of simulation the plant owner shall document the behaviour of the wind farm by application of a fixed voltage profile. […] The turbine test shall be done with the voltage profile shown in (the figure below) and shall show the behaviour of the wind farm in the case of a three-phase fault with a slowly recovering voltage"
Figure 5-2 Voltage Profile for Simulation of Three Phase Fault. Source: [20]
95
In the model at present used for this validation of turbine models similar to [15] no
protection system has been implemented.
During the system analysis a respective protection scheme will be implemented into the
wind farm equivalent.
5.4. Analysis of the Test System with SCIG Wind Turbine
5.4.1. Three Phase short circuit, UPCC = 0.2 p.u. In the test system a three-phase short circuit at the 110 kV bus has been simulated. The
duration of the fault was set to 150 ms. In the first case the reactance of the short circuit
was adjusted in order to obtain the desired level of the residual voltage at the 110 kV node
equal to 0.2 p.u., which was the requirement from [15]. For this purpose the reactance
XFAULT has been set to XFAULT = 1 Ω. The simulation was performed for the following
system configurations:
- without reactive power compensation,
- with reactive power compensation.
The results of the simulation for both configurations are shown in Figure 5-3 and in Figure
5-4, respectively.
From the obtained results it can be seen that the results without a reactive power
compensation unit in the test system modelled in PowerFactory differ significantly from the
ones given in [15]. If the above described assumed compensation unit has been
connected to the test system, the results are similar to the ones presented in [15].
However, some differences between the results in [15] and Figure 5-3 concerning the
profiles of current, voltage and reactive power after fault-clearing can be recognized.
These differences can be the consequence of different parameters used for system inertia
and for the compensation units in both compared systems.
This has been proven by variant calculations which have shown that a change of the
inertia to a significantly higher value, (e.g. to J=100000 kg m2) allows to obtain the
simulation results more similar to the ones given in [15], but this inertia is not realistic.
96
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9Time [s]
Volta
ge [p
u]
1
U_pcc
U_20kV
-100-75-50-25
0255075
100
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,1
0,2
0,3
0,4
0,5
0,6
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cur
rent
PC
C [k
A]
-3
-2,5
-2
-1,5
-1
-0,5
0
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Slip
[%]
Figure 5-3 Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.2pu) – without reactive power compensation
97
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9Time [s]
Volta
ge [p
u]
1
U_pcc
U_20kV
-100-75-50-25
0255075
100
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,1
0,2
0,3
0,4
0,5
0,6
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cur
rent
PC
C [k
A]
-3
-2,5
-2
-1,5
-1
-0,5
0
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Slip
[%]
Figure 5-4 Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.2pu) – with reactive power compensation
98
5.4.2. Three Phase short circuit, UPCC = 0.8 p.u.
In the second part of the analysis a three-phase short circuit with residual voltage equal to
0.8 pu was simulated at the 110-side of the PCC. For this purpose the fault reactance was
set to 15.5 Ω. The results are given in Figure 5-5 and Figure 5-6 for a case without and
with a reactive power compensation unit, respectively. The comparison of these results
with the ones presented in [15] shows the same trend as in case of the fault with residual
voltage UFAULT=0.2 pu (see above).
The inertia of the wind turbine system has a crucial influence on the behaviour during and
after the fault, since the reactive power drawn by the SCIG depends strongly on the
machine slip and this, in turn, depends on the inertia.
99
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9Time [s]
Volta
ge [p
u]
1
U_pcc
U_20kV
-75
-50
-25
0
25
50
75
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,1
0,2
0,3
0,4
0,5
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cur
rent
PC
C [k
A]
-2
-1,6
-1,2
-0,8
-0,4
0
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Slip
[%]
Figure 5-5 Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.8pu) – without reactive power compensation
100
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9Time [s]
Volta
ge [p
u]
1
U_pcc
U_20kV
-75
-50
-25
0
25
50
75
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,1
0,2
0,3
0,4
0,5
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cur
rent
PC
C [k
A]
-1,6
-1,2
-0,8
-0,4
0
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Slip
[%]
Figure 5-6 Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.8pu) – with reactive power compensation
101
5.5. Influence of Two – Mass Model Since the analysis from section 5.4 have been performed using a lumped – mass model
for the whole wind turbine (respectively upscaled wind farm equivalent), the characteristic
oscillations of the angular speed and therefore of the active and reactive power can be
neglected. In order to check the influence of a two-mass representation of the mechanical
system on the behaviour of the wind turbine the previously introduced model has been
enhanced according to [18].
The model is described with the following set of equations Eq. (10) – Eq. (14).
MMGMM
WTR DTTdt
dH ωω⋅−−=2 (10)
MGEGG
GEN DTTdt
dH ωω⋅−−=2 (11)
( )GMS
dtd ωωωθ
−⋅= 0 (12)
M
MM
PTω
= (13)
( )MGSSSG DKT ωωθ −⋅−⋅= (14)
Where: HWTR and HGEN – are inertia constants of turbine and generator, respectively,
ωM and ωG – are the angular speed of turbine and generator in pu, respectively, θS – is the
deflections angle of the soft shaft in elect. rad,
TM, TG, TE – are per unit torque generated by turbine, per unit torque applied to the
generator and per unit electromechanical torque of generator, respectively; DM, DG and DS
are the damping coefficients and KS is stiffness of the shaft in pu/rad.
The parameters used for the simulation of the two-mass mechanical system are
Table 13: Electrical Parameter of the Equivalent Farm Model
Parameter Value Inertia of the Turbine – JWTR 91.872·106 kg m2 Inertia Constant of the Turbine – HWTR 3.4999 Inertia of the Generator– JGEN 2050.84 kg m2 Inertia Constant of the Generator– HGEN 0.5 Stiffness Constant – kms 0.47746 pu/rad Gear Box Ratio – fGB=nGEN/nWTR 80
Table 14: Mechanical Parameter of the Equivalent Farm Model
The damping constants of the mechanical system were assumed to 0.
The size of the compensating capacitor at the terminals of the generator (0.69 kV level)
was equal to 39236 µF, which correspond to 17.65 MVar (Delta-circuit).
Fault reactance in case of URES=0.2pu is equal to 1Ω and in case of URES=0.8pu is equal to
15.5Ω.
106
5.7. Appendix - SCIG, Denmark
5.7.1. Simulation Results with PowerFactory – Load Flow
Figure 5-8 Load Flow Results in System without Compensation
107
Figure 5-9 Flow Results in System with reactive power compensation (Qrat=17.65 MVar)
108
5.7.2. Simulation Results with Two-Mass Model in PowerFactory
0
0,2
0,4
0,6
0,8
1
0 0,5 1 1,5 2 2,5 3 3,5 4 4,5 5Time [s]
Volta
ge [p
u]
U_pcc
U_20kV
-150
-100
-50
0
50
100
150
0 0,5 1 1,5 2 2,5 3 3,5 4 4,5 5Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,2
0,4
0,6
0,8
1
0 0,5 1 1,5 2 2,5 3 3,5 4 4,5 5Time [s]
Cur
rent
PC
C [k
A]
-100
-80
-60
-40
-20
0
20
0 0,5 1 1,5 2 2,5 3 3,5 4 4,5 5Time [s]
Slip
[%]
Figure 5-10 Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.2pu) – without reactive power compensation (Two-Mass Model)
109
0
0,2
0,4
0,6
0,8
1
0 0,5 1 1,5 2 2,5Time [s]
Volta
ge [p
u]
3
U_pcc
U_20kV
-75
-50
-25
0
25
50
75
0 0,5 1 1,5 2 2,5 3Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,1
0,2
0,3
0,4
0,5
0 0,5 1 1,5 2 2,5 3Time [s]
Cur
rent
PC
C [k
A]
-2
-1,6
-1,2
-0,8
-0,4
0
0 0,5 1 1,5 2 2,5Time [s]
Slip
[%]
3
Figure 5-11 Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.8pu) – with reactive power compensation (Two-Mass Model)
110
0
0,2
0,4
0,6
0,8
1
0 0,5 1 1,5 2 2,5Time [s]
Volta
ge [p
u]
3
U_pcc
U_20kV
-75
-50
-25
0
25
50
75
0 0,5 1 1,5 2 2,5 3Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,1
0,2
0,3
0,4
0,5
0 0,5 1 1,5 2 2,5 3Time [s]
Cur
rent
PC
C [k
A]
-2,4
-2
-1,6
-1,2
-0,8
-0,4
0
0 0,5 1 1,5 2 2,5Time [s]
Slip
[%]
3
Figure 5-12 Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.8pu) – without reactive power compensation (Two-Mass Model)
111
6. Validation of Wind Turbine Models - DFIG - in Denmark
(Wind Turbines with Doubly Fed Induction Generator)
6.1. Introduction This chapter describes the validation process of the wind turbine (WT) with doubly fed
induction generator (DFIG) in the PowerFactory simulation environment. The validation
process was performed according to the procedure included in [15]. Also the available
information about the parameters of the test system as well as about the machine
parameters has been taken from [15]. Some additional assumptions had to be made due
to lack of information in [15], which are described in this report giving some respective
recommendations.
6.2. Test System The test system defined in [15] has been implemented into PowerFactory as shown in
Figure 6-1
.
Figure 6-1 Test System Implementation into PowerFactory The parameters given for the system components are summarized in Table 15.
Table 18: Parameter of DFIG given in [15] transformed into p.u.-system as implemented into PowerFactory
The per unit parameters defined for the single wind turbine model has also been used for
the representation of the equivalent farm model. Moreover, in [15] the value of the wind
turbine´s active power Pn_FARM=30*Pn=45 MW is defined and this value has also been
assumed as rated power of the whole farm. For the given rated active power and
parameters of the machine equivalent circuit (as defined in Table 3) the apparent power of
the machine has been calculated by PowerFactory and is equal to 51.379 MW.
Since no other information about the test wind turbine was given in [15] some additional
assumptions had to be made. First, it has been assumed that the wind turbine can be
operated in the angular speed range corresponding to ± 20% of the generator slip.
Moreover, the parameters of the mechanical system as well as the structure of the
machine's control system have been assumed as will be discussed in section 6.3.3 and
section 6.3.4 of this report, respectively. It was also necessary to define in PowerFactory
the value of the rated slip ring voltage (with opened rotor circuit and standstill) which was
equal to UROTrat=1939 V.
In case of a wind turbine with DFIG the operational point, that is given by active and
reactive power as well as by the angular speed of the machine, can be varied in an
allowable range. In general, the active power output as well as the angular speed of the
turbine are determined by the control algorithms, which optimize the active power
production in partial load operation and limit the output power in full load operation. The
reactive power can be changed in order to support the grid voltage, however very often the
set point for reactive power is chosen to be equal to 0 Mvar.
In the simulations performed for this report the set point for active power has been
adapted to obtain about 45 MW on the 110 kV side of the test system, which corresponds
to the rated power of the farm. Moreover, it has been assumed that the generator operates
with -20% slip which corresponds to super-synchronous operation with an angular speed
115
equal to 1.2 pu. The reactive power of the generator has been set to 7 Mvar in order to
have the power factor equal to 1 in the point of common coupling on the 110 kV level while
the reactive power of the grid-side converter was equal 0 Mvar on the 0.69 kV node - so
that the reactive power demand of the connecting reactor (grid filter) has been
compensated.
6.3.3. Mechanical System Representation
The mechanical system of the wind turbine has been represented as two–mass model.
The block diagram of this system is shown in Figure 8 of [22]. The mechanical parameters
are summarized in Table 11. Parameter Value
Base Power – PBASE 5 MW Turbine Damping - DTUR 0 Nms/rad Inertia of the Turbine – JWTR 6.1·106 kg m2 Inertia of the Generator – JGEN 101.72 kg m2 Shaft Damping - DSHAF 1.4·106 Nms/rad Stiffness Constant – kms 8.3·107 Nm/rad Nominal Angular Speed of Turbine 18 rpm
Table 19: Mechanical Parameters of WT with DFIG (Rated Power 5MW) [23] Since the input and output signals of the mechanical system, as mechanical power of the
turbine and mechanical power transmitted through the shaft to the generator, are defined
in the model using the per unit system, the parameters defined in Table 19 have not been
modified, except the inertia of the equivalent generator, which was calculated according to
Eq. (17).
TURBGENEQV NJJ ⋅= (17)
Where NTURB=30 defines the number of individual wind turbines that are replaced by a
single equivalent farm model.
The resulting value of the equivalent generator inertia is equal to JEQV=101,72 kg m2 ⋅30
=3051.6 kg m2.
116
6.3.4. Control System of the Wind Turbine
6.3.4.1 Generator and Rotor Side Frequency Converter
The model of the wind turbine presented in [22] has been adapted in order to allow an
enhanced synchronization algorithm of the wind turbine generator with the grid after a fault
as discussed in [19] The goal of this control algorithm is to limit the excessive transient
current in the rotor of the machine during a fault and to protect the power electronic
converter connected to this rotor. For this purpose an additional resistance – crowbar – is
used to short-circuit the rotor while the commutation of the frequency converter is blocked.
If the crowbar is connected to the rotor circuit the doubly fed induction generator becomes
a regular induction generator with an additional resistance within the rotor circuit, which
influences the torque-slip characteristic of the machine. During this time period the
behavior of the machine – as reactive power exchange or electromechanical torque – can
not be controlled and therefore the machine will start to speed up and to absorb reactive
power from the grid, which causes decreasing of the voltage. Thus, the controllability of
the machine has to be restored as fast as possible, which happens by disconnecting the
crowbar and restarting the rotor side frequency converter. Depending on the wind turbine
manufacturer there are different schemes in which way the crowbar connection and
disconnection is proceeding. In this report the scheme described in [19] has been
followed.
The characteristic steps of this scheme are as follows:
1. insertion of the crowbar and blocking of the rotor side converter if the current limit in
the rotor circuit is exceeded,
2. disconnection of the crowbar and restart of the rotor side converter if the rotor current
is lower than the defined limit and the grid voltage is re-established,
3. synchronization of the wind turbine in order to reach the proper operational point
(regarding the active power – angular speed characteristic, as well as the reactive
power set-point).
117
The disconnection of the crowbar and restart of the converter can be a critical point, since
in this moment the rotor current might exceed the limit and the crowbar will be inserted
again. Therefore, at the moment of the crowbar disconnection the frequency converter has
to be synchronized to the respective point of operation. It means that the dq - components
of the voltage at the terminals of the rotor side converter must have a value which
corresponds to the voltage drop on the crowbar resistance. For this purpose the outputs of
the PI-controllers have to be adjusted to the desired value and at the same time a too fast
change of the controller outputs has to be avoided.
This has been realized in the extended wind turbine model as presented in Figure 6-5 to
Figure 6-7 in the appendix and will be discussed here. In the first step a non-windup PI
controller with reset possibility to a desired value has been implemented. The general
structure of this controller is shown in Figure 6-2. In normal state, when the trigger signal is
equal to zero, the switch is in position 1 and the controller operates on basis of the
measured value of the signal – XMEASURE and the reference value – XREF.
Figure 6-2 Block Scheme of a Non-Windup PI Controller with the Reset Function
In case of controller blocking the trigger signal is equal to 1 and the switch is in position 2.
In this operation mode the output of the PI - controller will be adjusted in order to have the
value equal to XRESET.
Moreover, in the control system of the rotor side converter the I – controller with reset
option has been used as well. The structure of this controller corresponds to that given in
Figure 6-2 with the proportional constant – K equal to zero.
118
The respective further gains and time constants for the used PI-controllers according to
Figure 6-6 and Figure 6-7 are defined in Table 20. In the used model the value of the KR-
parameter was set to 100.
Controller K T Rotor Active Power 0.1 0.01 Rotor Reactive Power
0.1 0.01
Rotor Current q-axis 0.44 0.01 Rotor Current d-axis 0.44 0.01 Grid Current d-axis 1. 0.015 Grid Current q-axis 3. 0.015 DC-Voltage 5 0.1 Both I-controllers in Rotor Power Controller
--- 1
Reset Gain KR 100 --- Table 20: Gains and time constants for used PI-controllers
Using the introduced PI and I – controllers the control system for active and reactive power
has been developed as shown in Figure 6-6. The inputs to this model are summarized in
Table 21 and outputs in Table 22, respectively. Input No.
Signal Description
0 bypass from protection module (equal to 1 if crowbar activated and immediately 0 if crowbar deactivated)
1 bypdelP from protection module (equal to 1 if crowbar activated and set to zero first if the active power controller synchronized)
2 Pref reference value of the active power from MPT (maximal power tracking) controller
3 P measured value of the active power in the PCC
4 Ifq measured value of the rotor current in the q-axis
5 Qref reference value of reactive power usually set constant to keep unitary power factor, but can be used to support the grid voltage
6 bypdelQ from protection module (equal to 1 if crowbar activated and set to zero first if the reactive power controller is synchronized)
7 Q measured value of the reactive power in the PCC
8 Ifd measured value of the rotor current in the d-axis
Table 21: Input Description of the Power Controller from Figure 6-6
119
Output
No. Signal Description
0 Pref_INT value of the output of the I-controller used for active power control
1 Ifq_ref reference value of the rotor current in the q-axis, which is used as input for the current controller
2 Ifd_ref reference value of the rotor current in the d-axis, which is used as input for the current controller
3 Qref feed-through of the Qref input for using in other blocks
4 Qref_INT value of the output of the I-controller used for reactive power control
Table 22: Output Description of the Power Controller from Figure 6-6
During normal operation, i.e. the crowbar is disconnected and therefore the signals
"bypass", "bypdelP" and "bypdelQ" are zero, the value of inputs “yi” and “yi1” (see Figure
6-6) for active and reactive power controllers “x1” and “x2” are calculated according to Eq.
(18) and Eq. (19), respectively.
P1Prefyi −= (18)
Q1Qrefyi1 −= (19)
In case the rotor current exceeds the defined limit the crowbar is activated and signals
"bypass", "bypdelP" and "bypdelQ" become 1. In this situation the states of all switches
change to the opposite state (i.e. to the internal switches of PI and I – controllers, as
shown in Figure 6-2 ) and the controller is in the emergency modus. In this modus all PI
and I – controllers are reset to an appropriate value in order to avoid the transients when
the crowbar will be deactivated. In the power controller the output signals – "Ifd_ref" and
"Ifq_ref", which are then used as input signals for the current controller, are set equal to
the measured rotor current components in the d and q axis, respectively. This guarantees,
that, after return to the normal operation mode from the emergency mode, the inputs for
the PI – controllers of the current controller will be equal to zero and no immediate step-
wise change of the modulation indexes "Pmd" and "Pmq", which correspond to the voltage
applied to the rotor, will be present. During the emergency operation the both modulation
indexes "Pmd" and "Pmq" are set to zero through the change of the switch position “S5”
and “S6”. At the same time the outputs of PI-controllers “x3” and “x4” are reset to the
values “Pmqref” and “Pmdref”, respectively. These values are calculated in the block
120
"current measurement" (see Figure 6-5 in appendix) using the measured values of the d
and q components of the rotor current as well as of the crowbar resistance and correspond
to the voltage drop on the crowbar resistance.
6.3.4.2 Grid-Side Frequency Converter
In general, the grid side frequency converter is responsible for controlling the voltage level
in the DC circuit as well as for the controlling of the reactive power exchange with the grid.
Therefore, it can be used as SVC unit for support of the grid voltage. The control system of
the grid side frequency converter used in the presented model is described in [22].
6.3.5. Protection System - Crowbar
6.3.4.3 General Remarks The protection system of wind turbines with doubly fed induction generators is more
sophisticated as in case of wind turbines with conventional asynchronous generators,
which usually are equipped with under- and over-voltage protection and trip immediately if
the lower or upper limit is exceeded.
The wind turbines with doubly fed induction generator, however, are obliged to stay
connected to the grid during a grid fault and to support the power system operation. Since
specific parts of these units, as frequency converters, are very sensitive to over-currents,
an appropriate protection scheme has to be applied. As already discussed in the previous
section the protection of the frequency converters is realized by the insertion of an
additional resistance (crowbar) into the rotor circuit and disconnection (blocking) of the
converter.
The challenge is the return to normal operation, because not proper disconnection of the
crowbar and activation of the converter can lead to excessive current transients and to a
re-activation of the crowbar. Therefore, the operation of the converter controllers as well
as the state of the crowbar is controlled by the protection system that generates the logic
control signals. The possible operational states of the wind turbine as well as of the
protection system are shown in Figure 6-3. Three states can be distinguished:
121
normal state,
- emergency state and
- resynchronization state.
Between these states there are transition conditions T1 – T3. In order to change from one
state to another the transition conditions between the considered states have to be
fulfilled.
The transition condition T1 are fulfilled if the measured value of the rotor current exceeds
the defined limit, the transition conditions T2 are fulfilled if the grid voltage is reestablished
and the transition conditions T3 are fulfilled if the controllers of the rotor side converter are
reset to the desired values and the unit is synchronized to the existing conditions (as wind
condition, grid voltage conditions). In this model the limit of the rotor current was set to 1,5
times the base rotor current and its value is given by Eq. (20).
kAII ROTbaseROT 45.325.1max =⋅= (20)
The rotor base current is defined as given by Eq. (21).
AV
MVAU
SIROTrat
ratROTbase 27.21635
31939379.512
32 =
⋅=
⋅=
(21)
In normal state the crowbar is disconnected and the controllers are following the defined
reference values of the active and reactive power. In this state the logic control signals –
"bypass", "bypdelP" and "bypdelQ" equal to zero. If the wind turbine is in emergency state
the crowbar is active and the controllers are reset to the appropriate value while the rotor-
side-converter is blocked. In this state all control signals of the protection system equal to
one.
If the voltage is reestablished the crowbar is disconnected and the rotor side converter
supplies the rotor with the voltage corresponding to the voltage drop at the crowbar
resistance. The unit is now in resynchronization state. In this state not all controllers are in
normal operation since only the "bypass" – signal is equal to zero, since the crowbar has
been disconnected. The other signals "bypdelP" and "bypdelQ" are meanwhile equal to
one until the outputs of both I – controllers are different than present reference values for
122
active and reactive power. If the reference value of active power "Pref" is equal to the
output from the I-controller the signal "bypdelP" is set to zero and similar in case of the
signal "bypdelQ" but here the "Qref" is observed.
Figure 6-3 Operational States of the Protection System
123
6.3.4.4 Influence of Crowbar Resistance Size on the Machine Behaviour
An important aspect is also the value of the crowbar resistance since it has influence on
damping of current transients in the rotor circuit. Since there was no information in [15]
about the size of the crowbar resistance its value was chosen for the validation at hand
according to the recommendations given in [19]. These recommendations say that an
optimal value for the crowbar resistance is equal to 20 times the resistance of the rotor
circuit. Therefore, for the given parameters of the generator (see Table 2 and Table 3) the
crowbar resistance used for the analysis at hand is equal to
RCROW=20 x 0.008pu = 0.16pu. In the appendix the influence of the crowbar resistance on
the wind turbine behavior during a 3-phase fault is shown (see Figure 5-10).
6.4. Analysis of the Test System with DFIG Wind Turbine In the test system a three-phase short circuit at the 110 kV bus has been simulated. The
duration of the fault was set to 150 ms. In the first case the reactance of the short circuit
was adjusted in order to obtain the desired level of the residual voltage at the 110 kV node
equal to 0.2 p.u., which was the requirement from [15]. For this purpose the reactance
XFAULT has been set to XFAULT = 1 Ω.
In the second case the short circuit reactance was equal to XFAULT = 15.5 Ω, which results
in residual voltage equal to 0.8pu in the point of common coupling. The simulation results
for both cases are shown in and Figure 6-9 of the appendix, respectively.
Both figures show significant differences in comparison to the results presented in [15].
The main reasons for these differences results from the fact, that the test wind turbine has
not been completely specified in [15], i.e. control system structure, mechanical system,
protection system and their parameters. Thus, different behaviour is possible.
The behavior of the wind turbine with DFIG depends mainly on the control algorithm. But
also such parameters like crowbar resistance have a significant influence on the dynamic
behavior, especially after fault clearing, see Figure 5-10.
124
In the next chapter the parameter settings developed in this report will be summarized.
6.5. Conclusions and Recommendations This report discusses an exemplary modeling approach of the wind turbine with DFIG that
has been developed on basis of [15] and [22].
The analysis described in this paper shows that the detailed definition of all parameters of
the test system is crucial for the simulation results using different software. As already
discussed in [24] the main reason for the differences between simulation results are not
completely defined parameters of the model components and its structure in [15] thus,
some recommendations have been made in this report.
Therefore, in order to obtain similar simulation results a more detailed description of the
model is required, or the model in [15] should be adapted to the recommendations of this
report.
This concerns, first of all, the structure and the parameters of the control system (rotor-
side converter, grid-side converter, crowbar initialization and disconnection conditions and
corresponding logic), but also the uniform representation and the parameters of the
mechanical system.
Moreover, the structure and the parameters of the DC-circuit (voltage level, size of
capacitor) as well as the size of the grid filter used for interconnection of the grid-side
converter have to adapted respectively.
125
6.5.1. Recommendations for Simulation Settings The following settings are recommended:
Table 23: Summary of electrical parameter settings developed in this chapter. *) Such a high value results from the assumption of the basis current for the rotor in PowerFactory
Parameter Value Base Power – PBASE 5 MW Turbine Damping - DTUR 0 Nms/rad Inertia of the Turbine – JWTR 6.1·106 kg m2 Inertia of the Generator – JGEN 101.72 kg m2 Shaft Damping - DSHAF 1.4·106 Nms/rad Stiffness Constant – kms 8.3·107 Nm/rad Nominal Angular Speed of Turbine 18 rpm Inertia of Equivalent Generator - JEQV=30xJGEN
3051.6 kg m2
Table 24: Summary of mechanical parameter settings developed in this chapter. Fault reactance in case of URES=0.2pu is equal to 1Ω and in case of URES=0.8pu is equal to
15.5Ω.
126
6.6. Appendix DFIG - Denmark
6.6.1. Simulation Results with PowerFactory – Load Flow
Figure 6-4 Load Flow Results in the Test System with DFIG (P=45MW; Q=0Mvar, slip=-
20%)
127
6.6.2. Block Diagrams of the Enhanced Wind Turbine Model
Figure 6-5 Block Diagram of the Model Representing the Generator and Rotor-Side
Converter
128
Figure 6-6 Block Diagram of the Model Representing the Power Controller
129
Figure 6-7 Block Diagram of the Model Representing the Current Controller
130
6.6.3. Simulation Results for Dynamic Analysis
0
0,5
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cro
wba
r
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Volta
ge [p
u]
U_pcc
U_20kV
-100
-50
0
50
100
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Act
.- &
Rea
ct. P
ower
P_pcc [MW]
Q_pcc [Mvar]
0
0,2
0,4
0,6
0,8
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cur
rent
PC
C [k
A]
131
-50
-25
0
25
50
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Rot
or C
urre
nt [k
A]
abc
-3
-2
-1
0
1
2
3
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cur
rent
PC
C [p
u]
RealImag
1
1,1
1,2
1,3
1,4
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Ang
ular
Spe
ed [p
u]
Figure 6-8 Simulation Results of 3-phase fault at 110 kV node
6.6.4. Influence of Crowbar Resistance on Behavior of the Machine
0
0,5
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cro
wba
r
Rcrow =0.16
Rcrow =0.016
Rcrow =0.36
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Volta
ge P
CC
[pu
]
Rcrow =0.16
Rcrow =0.016
Rcrow =0.36
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Volta
ge 2
0kV
[pu]
Rcrow =0.16
Rcrow =0.016
Rcrow =0.36
-75
0
75
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Act
. Pow
er P
CC
[MW
]
Rcrow =0.16
Rcrow =0.016
Rcrow =0.36
135
-150
-75
0
75
150
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Rea
ct. P
ower
PC
C [M
var]
Rcrow =0.16
Rcrow =0.016
Rcrow =0.36
0
0,2
0,4
0,6
0,8
1
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Cur
rent
PC
C [
kA] Rcrow =0.16
Rcrow =0.016
Rcrow =0.36
1,1
1,15
1,2
1,25
1,3
0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1Time [s]
Ang
ular
Spe
ed [
pu]
Rcrow =0.16
Rcrow =0.016
Rcrow =0.36
Figure 6-10 Influence of Crowbar Resistance on Simulation Results of 3-phase fault at 110 kV node (tFAULT=150ms, UFAULT=0.2pu, Two-Mass Model, Different Crowbar Resistances)
136
7. References
[1] CIGRE Technical Brochure on Modeling and Dynamic Behavior of Wind Generation as it
relates to Power System Control and Dynamic Performance; Working Group 601 of Study
Committee C4, Final Report January 2007.
[2] Nicholas W. Miller, William W. Price, Juan J. Sanchez-Gasca: Stability Modeling of Vestas
V80 Wind Turbine-Generator (Version 2.0); GE Energy, March 2003.
[3] Rudion, K.; Ruhle, O., Styczynski: Simulation of Large Wind Farms using Coherency
Approach; Eurosim 2007, Sept. Ljubljana, Slovenia.
[4] Soens, J.: Impact of Wind Energy in A Future Power Grid; PhD Thesis, Katholieke
Universiteit Leuven, Belgium, 2005.
[5] Petersson, A.: Analysis, Modeling and Control of Doubly-Fed Induction Generators for Wind
Turbines. Ph Thesis, Chalmers University of Technology, Göteborg, Sweden 2005.
[6] G. Duschl, H.-D. Pannhorst, O. Ruhle - SIEMENS AG, Erlangen Dynamic simulation of
DFIGs for wind power plants using NETOMAC, Workshop for Wind power integration,
Glasgow, 2005
[7] Erlich, I.; Winter, W.; Dittrich, A.: Advanced Grid Requirements for the Integration of Wind
Turbines into the German Transmission System, IEEE PES General Meeting, Montreal 2006.
[8] “Procedimiento de Operación “P.O.12.3 – Requisitos de respuesta frente a huecos de
tensión de las instalaciones de producción de régimen especial”. Red Eléctrica de España.
B.O.E. . October 2006. http://www.ree.es/operacion/procedimientos_operacion.asp
[9] “Procedimiento de verificación, validación y certificación de los requisitos del Procedimiento
de Operación 12.3 sobre la respuesta de las instalaciones eólicas ante huecos de tensión”.
January 2007; Available on: http://www.aeeolica.org/
[10] “IEC 60909. Short-circuit currents in three-phase a.c. systems” July 2001
[11] Akhmatov V.: Analysis of Dynamic Behavior of Electric Power System with Large Amount of
Wind Power, PhD. Thesis available on http://www.oersted.dtu.dk/eltek/res/phd/00-05/va-thesis.pdf